Canada is best known, and most dear, to renewables developers for its 20- to 25-year contracts with highly-rated public utilities. Wind, while insignificant next to hydro in the country's energy mix, is tipped to reach 12GW by 2015, although just 2,369MW was in place at the end of 2008.

Canada's provinces each operate their own renewables regime, though they all offer generators clear and robust offtake structures that make them the envy of their UK and US peers. Dean Cooper, head of alternative energy at investment bank Ambrian in London argues returns are higher in the UK, for example, but companies target Canada because of the stable revenues. "They trade the longer duration [contracts] against the lower tariff."

The right time for Europeans?

The various provinces have begun to attract attention from the larger European developers, including GDF Suez, which bought local developer Ventus Energy in 2007, and Acciona. Both won contracts in New Brunswick under a May 2007 request for proposals (RFP) for 300MW of wind.

Others are more hesitant. Shortly after E.On bought Airtricity's North America business, Airtricity won three of the 14 projects that Hydro Québec selected as part of a 2GW tender. E.On was reportedly uncomfortable with the investment and pulled out. "E.On wasn't familiar with the market, so decided they were not as interested any more," says Marion Hill, section head for independent expert opinions on wind at consultant Helimax Energy. Spanish developer Enerfin is behind one of the four projects, including one additional project that replaced Airtricity's.

Domestic players, however, still predominate, especially those formed by entrepreneurs or oil and gas companies such as Enbridge, Inc. Small developers could look to listing on the TSX Venture Exchange, and their ability to raise equity capital – before the stock market soured, at least – gave them the means to ramp up quickly. But these developers, feeling that their market capitalisation does not reflect the value of their capacity, are reluctant to issue new shares. Private companies are actually finding it easier to raise money, according to John McIlveen, research director at boutique investment bank Jacobs & Co.

To stay viable, several start-ups have been forced to bring in outside equity, often at the project level. "Everybody is trying to do it," adds McIlveen. Developers are also pursuing asset sales, as evidenced by Finavera Renewables' decision to sell its 75MW Ghost Pine wind farm in December. Creststreet Power & Income Fund flipped its 30.6MW Pubnico Point and 54MW Mount Copper wind farms to FPL Energy for a combined C$121.6 million ($100 million). Alban De la Selle, managing director at Dexia Credit Local, says he is also seeing a slew of private companies trying to sell small hydro plants to raise cash because they deem the assets non-core.

Crunch time

As with the country's PPP market, Canadian banks have by and large steered clear of arranging roles in renewables, leaving the field clear for European, US and Japanese banks. Nevertheless, Scotia closed a C$194 million financing for Kruger Energy's 101MW Port Alma wind project in Ontario in April 2008.

Since the crunch hit with a vengeance, foreign players have moved to the fore. Fortis led the financing for an AIM PowerGen project under Ontario's Standard Offer Program, and Innergex closed on the financing for its 38% stake in the 109.5MW Carleton wind project with SMBC and Bank of Tokyo Mitsubishi-UFJ. In November, Nord/LB closed Canada's first solar project financing for phase one of a 19MW facility owned by SunEdison and SkyPower.

It is telling there have not been more. Banks are reducing their lists of acceptable contractors and turbine manufacturers. Sponsors need to incorporate larger debt service reserves, now covering as much as six months' shortfall, where previously they had been happy with as little as three. Maturities have fallen to a maximum of seven years and spreads have widened to at least 300bp from around 125-140bp over CDOR, according to Dexia's De la Selle.

Banks have generally pushed for leverage on projects to fall as low as 65-70% from a more typical 75-80%. Some, such as Western GeoPower, have not only obtained loans at high interest rates but have had to tack on warrants. Kent Brown, CFO of Canadian Hydro Developers, says there is a genuine risk that small developers will struggle to obtain capital. Canadian Hydro's most recent financings were completed over the summer, just before the markets took a turn for the worse.

In June it issued a C$79 million, 10-year bond, which carried a coupon of 7.1% and was led by BMO and Scotia Capital, to refinance its acquisition of 99MW Le Nordais in Quebec. At the same time it increased its C$370.8 million in corporate debt to C$611 million. The debt previously included C$233.5 million in two-year construction facilities for the Melancthon II wind and Blue River hydro projects, priced at 70bp over CDOR, C$72.3 million in debt for Nordais, which has been retired, and a C$65 million revolver, which was increased by C$20 million.

Rounding out the increased amount was a C$292.5 million construction loan for the Wolfe Island wind project, which, like the revolver, was priced at 137.5bp. The lead arrangers and bookrunners were TD and Scotia, while National Bank of Canada was documentation agent, and Alberta Treasury Branches, Societé Générale, SMBC, UBOC, Canadian Western Bank and Laurentian Bank participated.

In the circumstances, arrangers looking to build market share and developers anxious to prove their credentials can form alliances. GE Energy Financial Services put together a joint bid with Plutonic for a 160MW contract in the British Columbia call for power, and repeated the tactic with Finavera on four wind projects in Vancouver. Donald McInnes, vice-chairman and CEO at Plutonic, said he negotiated the deal with GE before finishing development and securing the power purchase agreement.

GE committed roughly C$150 million to Plutonic's 196MW East Toba and Montrose Creek run-of-river hydro projects in 2007. Next up are a project in the Bute Inlet, in which GE is lined up to buy a 60% stake for around C$650 million, and 130MW Upper Toba, which GE can buy half of for C$70 million.

As banks struggle with liquidity and funding issues, competition could come from life insurers such as Manulife Financial, Sun Life Financial and Canada Life, which offer longer-dated fixed-rate debt. Life insurers committed 38-year debt to Plutonic's 2007 financing, and the life companies say that they are still open to developers. "We are responding to requests from clients who are looking for financing, so once they've got a contract we're good to go," says Bill Sutherland, senior managing director in project financing at Manulife.

How not to screen the losers

But a prominent early-stage role for debt arrangers, which again has more in common with the bidding for PPP projects, is designed to soothe offtaker concerns. The Ontario Power Authority looks for a track record and tangible net worth, says Canadian Hydro's Brown. According to OPA tender documents: "[A] proponent must demonstrate that it has successfully financed another generation facility within the last 60 months that is at least 50% of the contract capacity of the proposed [facility]." It also asks that one equity provider account for at least 20% of the project cost, a deposit of $25,000 per MW of capacity up to a maximum of $1 million, and a standby letter of credit from a bank with a minimum credit rating.

BC Hydro typically does not ask for a security deposit but does want a proposal submission fee, depending on the size of the project, and a non-refundable registration fee of $5,000. In its latest call, it also asked for financing commitments as part of each bid. It likes to see "viable projects that complement [its] grid," said spokesman Dag Sharman. Roughly 43 proponents submitted 68 projects – potentially generating more than 17GWh per year – in November for BC Hydro's call for 3GW. It expects to sign contracts in the middle of 2009, pending approval from the utilities commission.

Typically, the procurement process comes down to who bids the best price, and some provinces can be much more trusting than others. Although questions have been raised over the creditworthiness of Babcock & Brown amid a push by its parent to shed assets, Manitoba Hydro surprised the market by selecting the company from about 84 proposals for its 300MW wind call, which had been issued in 2007. "They are expecting an ability to deliver the turbines and the financing but at the end of the day my sense is they are probably chasing the lowest price project," said Colin Edwards at Babcock & Brown.

B&B bought the winning St. Joseph wind farm from Calgary-based BowArk Energy in July 2007, attracted to its closeness to a main export substation, adds Edwards. The PPA is still under negotiation but the project is expected to come online in 2010 or early 2011. "We're looking at all financing plans. It's impossible to figure out what the long-term optimal capacity structure will be, but our expectation is that the project finance market will return to normal within the project's life," he says.
There is a risk that some recently-awarded contracts will not proceed. "There are newer companies created to take advantage of the opportunity where people have not done enough homework and could not get them financed," says McInnes. Robert Hornung of the Canadian Wind Energy Association agrees. "The [utilities] are so focused on the lowest cost outcomes, it provides a real risk that developers will bid too low."

In British Columbia, smaller companies have a chance to compete but BC Hydro plans for an attrition rate of 30%, compared to around 90% in Ontario. In Nova Scotia, there is around a 50% success rate for bringing projects into construction, according to Peggy Cameron, a vice-president at start-up Black River Wind. After meeting its 246MW target for wind in May 2008, Nova Scotia Power launched a fresh RFP for 20MW of wind or solar and for 10MW for biomass in December. But developers say that it should be offering more.  "RFPs in Nova Scotia are as underwhelming in their success as in any other jurisdiction where that model for renewables is used," Cameron laments.

Not even developers with a fixed-price PPA are safe. Cost overruns and a lower than expected wind capacity at its Dokie I project led Earthfirst Canada to file for protection under the Companies' Creditors Arrangement Act. The company ran a strategic review for either an outright sale of the company or asset sale, advised by Blair Franklin Capital Partners and GMP Securities, but could not find a buyer in time to avert filing. Separately, Marathon Capital is handling the sale of the Vestas turbines on site. The company says it is in talks with potential buyers and will need to close a sale before March. Earthfirst's creditor under a turbine supply loan is WestLB, which has so far granted some room to EarthFirst to restructure.

Turbines are being marketed at big discounts. Until recently developers had to join a two-year waiting list and then suffered when the Canadian dollar weakened in 2008. A promising sign is the arrival of Quebec-based turbine maker Aaer, which could benefit from Hydro Quebec's insistence on bidders using a certain amount of local equipment on their projects.

No Cakewalk

But the new Canadian federal budget signed at the end of January did not renew the ecoEnergy program, a key subsidy for renewable projects. Ontario has had regular, predictable calls over the last few years, but other provinces have been more sporadic and changeable in their calls for power. Utilities that hold to a schedule are the places to invest, says Canadian Hydro's Brown. An already jittery lending community might find its patience worn thin by such unpredictability.

One area of inconsistency has been electrical interconnection rules. In some cases, winning projects were promised a place higher up the interconnection queue. "It made it difficult for developers to understand the value of their queue position," says Hill at Helimax.